A Simulation Study of Simultaneous Acid Gas EOR and CO2 Storage at Apache… · 2015-10-28 ·...
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A Simulation Study of Simultaneous Acid Gas EOR and CO 2 Storage at Apache’s Zama F Pool Dayanand Saini, Damion J. Knudsen, James A. Sorensen, Charles D. Gorecki, Edward N. Steadman, and John A. Harju Energy & Environmental Research Center, University of North Dakota, Grand Forks, North Dakota EERC Energy & Environmental Research Center ® Putting Research into Practice © 2012 University of North Dakota Energy & Environmental Research Center GHGT-11 – 2012 Abstract The Plains CO 2 Reduction (PCOR) Partnership is working with Apache Canada Ltd. (Apache) to validate the stored amount of CO 2 during ongoing enhanced oil recovery (EOR) operation at the F pool of the Zama oil field situated in northwestern Alberta, Canada. Apache is capturing CO 2 and H 2 S from a nearby gas-processing plant and injecting this stream into the F pool for simultaneous EOR and CO 2 storage. Acid gas injection was initiated in December 2006 and is continuing to date. The present compositional flow simulation study aims to evaluate ways for maximizing incremental oil recovery and CO 2 storage capacity in this depleted and closed pinnacle reef structure. Two different versions (Version 1 and Version 2) of a constructed static geologic model were used for performing dynamic simulations. In the first simulation scenario that used, the Version 1 static model, additional storage capacity gain by pressure management through water extraction (no oil production) from the water zone below the oil–water contact (OWC) was investigated. The results clearly indicate the viability of formation water extraction for increasing storage capacity in a closed geologic structure. The second iteration of the constructed static geologic model (Version 2) was chosen for simulating cases of continuing the current EOR scheme with and without a bottom water extraction well. A fivefold (0.30 million metric tonnes [MMt] to 1.22 MMt) increase in CO 2 storage capacity was observed with a bottom water extraction well compared to the case with no bottom water extraction well. This scheme also results in an incremental EOR recovery of 22.1% in the next 20 years, which is 5% more compared to the case of the existing EOR scheme (no bottom water extraction well). With over 700 pinnacle reef structures (oil-bearing or water-bearing) in the Zama subbasin, a careful selection of pinnacle structures similar to the F pool may provide significant storage capacity gain through water extraction from the underlying water zone (aquifer) while achieving a significant increase in oil recovery. Petrophysics • History matching was performed with P10 OOIP (original oil in place) static model realization. • A combination of object modeling and MPS workflow was used for spatial distribution of reef and nonreef facies in the static model. • The adjusted parameters include vertical permeability, well productivity indices, and volume modifier for the reef structure below the OWC, along with a numerical aquifier at the bottom of the structure. History Matching (Version 2 model) Low-Permeability Rock Type Facies High-Permeability Rock Type Facies Input Output GR NPHI PHOB PEF DT RT RXO Facies PHE Kh Kv Perfs Swn Son Sw So 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 0 0.2 0.4 0.6 0.8 1 Krog Krg Sl, fraction Low-Permeability Rocks (gas/oil rel. perm.) Krg (initial) Krog (initial) Krg (history-matched) Krog (history-matched) 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 0 0.2 0.4 0.6 0.8 1 Krw Krow Sw, fraction Low-Permeability Rocks (oil/water rel. perm.) Krow (initial) Krw (initial) Krow (history-matched) Krw (history-matched) 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 0 0.2 0.4 0.6 0.8 1 Krog Krg Sl, fraction High-Permeability Rocks (gas/oil rel. perm.) Krg (initial) Krog (initial) Krg (history-matched) Krog (history-matched) 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 0 0.2 0.4 0.6 0.8 1 Krw Krow Sw, fraction High-Permeability Rocks (oil/water rel. perm.) Krow (initial) Krw (initial) Krow (history-matched) Krw (historty-matched) Simultaneous CO 2 EOR and Storage 0 20000 40000 60000 80000 100000 120000 140000 0 2000 4000 6000 8000 10000 12000 14000 Cumulative CO 2 Injection, metric tonnes Cumulative Oil, m 3 Date Cumulative Oil and Injected CO 2 Zama F Pool Cumulative Oil Production (m 3 ) Cumulative Acid Gas Injection (Metric tonnes) Cumulative CO 2 Injection (metric tonnes) Cumulative CO 2 Production (metric tonnes) Net CO 2 Stored PVT (pressure, volume, and temperature) Modeling • An 11-component Peng–Robinson equation of state (EOS) PVT model was developed to use in the compositional simulation. • Simulated minimum miscibility pressures (MMPs) were 4.1% higher and 5.5% lower than the measured values for pure CO 2 and acid gas (80% CO 2 + 20% H 2 S) mixture, respectively. 1.00 1.05 1.10 1.15 1.20 1.25 0 10 20 30 40 50 60 70 80 0 5000 10000 15000 20000 25000 30000 35000 40000 Relative Oil Volume (ROV) ,rm 3 /m 3 Gas–Oil Ratio (GOR), m 3 /m 3 Pressure, kPa Differential Liberation Test Regression Summary Final GOR Init. GOR Exp. GOR Final ROV Init. ROV Exp. ROV 0.001 0.002 0.003 0.004 0.005 0 5000 10000 15000 20000 25000 30000 35000 40000 Oil Viscosity, Pa-s Pressure, kPa Differential Liberation Calculation Regression Summary Final Oil Visc. Init. Oil Visc. Exp. Oil Visc. Static Modeling Workflow Step 4. Form Reservoir Model Anhydrite Wackestone/Packstone Grainstone/Floatstone/Rudstone (10s of m-to-km scale) Permeable Facies Permeable Facies Tight Facies (nm-to-mm scale) Step 2. QEMSCAN (cm-to-m scale) Step 3. Formation Microimaging Log Processing and Petrophyscics Step 1. Micro-CT scan (nm-to-μm scale) Dolomite Background Calcite Others Quartz HiBSE Halite Pore Porosity Matrix The Sequential Gaussian simulation algorithm was use to populate reservoir properties in the model. History Match Results for Cumulative Oil, Water, and Gas Volumes Actual and Simulated Well Bottomhole Pressures (8HPs) History Match Results for Cumulative Volumes of Injected Acid Gas and Water Predictive Simulation Results Formation Water Extraction Assisted by Acid Gas Injection (no oil production), Version 1 model Existing EOR Configuration (one gas injection and two production wells) Two scenarios with minimum well BHP (bottomhole pressure) constraint of 2068 kPa (300 psi ) and 14,478 kPa (2100 psi) at production wells 0.08 0.81 1.08 1.05 1.04 0.85 1.02 0.05 0.47 0.62 0.68 0.69 0.49 0.60 0.62 0.85 0.91 0.94 0.72 0.84 0.00 0.20 0.40 0.60 0.80 1.00 1.20 One Injector (0.113 MMt/year) No Extractor, (Case 1) One Injector (0.113 MMt/year) One Extractor (Locaon Y, 516 m 3 /day), (Case 2) One Injector (0.113 MMt/year) One Extractor (Locaon Z, 516 m 3 /day), (Case 3) One Injector (0.113 MMt/year) One Extractor (Locaon Z, 429 m 3 /day), (Case 4) One Injector (0.113 MMt/year) One Extractor (Locaon Z, 397 m 3 /day), (Case 5) One Injector (0.227 MMt/year) One Extractor (Locaon Z, 1144 m 3 /day), (Case 6) One Injector (0.227 MMt/year) xE6 Volume or Mass of Injected Acid Gas and Extracted Water, Closed Boundary System Cumulave Extracted Water Volume at Reservoir Condions, m 3 Cumulave Injected Acid Gas Mass (Storage Capacity) at Standard Condions, tonnes Cumulave Injected Acid Gas Volume at Reservoir Condions, m 3 Two Extractors (Locaons Z and Z1, 1144 m 3 /day), (Case 7) Initial Oil Saturation Oil Saturation at the End of History Match Period (2012-06-01) Gas Saturation at the Start of Gas Injection (Dec. 2006) Gas Saturation at the End of History Match Period (2012-06-01) Total Gas per Unit Area (m) at the End of History Match Period (2012-06-01) Gas Saturation (2032-06-01) 1 Total Gas per Unit Area (m) (2032-06-01) 1 Total Gas per Unit Area (m) at the Start of Gas Injection (Dec. 2006) Oil Saturation (2032-06-01) 1 1 After 20 years of EOR operations, minimum BHP constraint of 2068 kPa (300 psi) at production well. Additional CO 2 Storage Capacity Gain Through Water Extraction One water extraction well completed in bottom water zone with existing EOR configuration (one gas injection and two oil production wells). Reservoir Pressure Behavior During Acid Gas EOR and 50-year Postinjection Period Predictive Simulation Results (continued) Time, date Average Reservoir Pressure, kPa 1970 1980 1990 2000 2010 2020 2030 2040 2050 2060 2070 2080 2090 2100 5,000 10,000 15,000 20,000 25,000 30,000 Bibliography Buschkuehle M, Haug K, Michael K, Berhane M. Regional-scale geology and hydrogeology of acid- gas enhanced oil recovery in the Zama oil field in Northwestern Alberta. Report prepared by Alberta Energy and Utilities Board and Alberta Geological Survey, Canada, for the Plains CO 2 Reduction Partnership at the Energy & Environmental Research Center, 2007. Burke L. PCOR project Apache Zama F pool acid gas EOR & CO 2 storage. Report prepared by RPS Energy Canada for the Energy & Environmental Research Center, 2009. Knudsen DJ, Saini D, Gorecki CD, Peck WD, Sorensen JA, Steadman EN, Harju JA. Using multiple-point statistics for conditioning a Zama pinnacle reef facies model to production history. Poster presented at American Association of Petroleum Geologists (AAPG) annual conference and exhibition, Long Beach, CA, 2012. Asghari K. Zama Keg River F pool field-scale CO 2 -flood simulation study. Report prepared for Apache Canada Ltd., 2005. Acknowledgments This material is based upon work supported by the U.S. Department of Energy National Energy Technology Laboratory under Award No. DE-FC26-05NT42592. Financial support from the U.S. Department of Energy to perform this work is greatly appreciated. The authors would like to thank Apache for providing necessary data to perform this work. The generous software support of Schlumberger and Computer Modelling Group Ltd. is gratefully acknowledged. The authors acknowledge Megan Grove and the members of the EERC’s Editing and Graphics staff for their help with poster preparation. Summary The results of detailed static and geologic modeling performed in this study suggest that water extraction from underlying water zone (aquifer) can effectively be used for additional gain in both oil recovery and CO 2 storage capacity in a closed system like the Zama F pool. The availability of additional pore space in the water zone below the OWC through controlled water extraction has resulted in a significant increase in F pool storage capacity. A combination of topdown gas injection EOR coupled with bottom water extraction appears to provide a new way to increase overall recovery efficiency and storage capacity in such reservoirs. In view of the high salinity of the formation water, produced water can be injected into another formation if a suitable completion strategy like downhole water sink (DWS) is used to complete water extraction wells. With over 700 pinnacle reef structures in the Zama subbasin, a careful selection of eight (EOR with bottom water extraction) to 16 (water extraction, no oil production) can provide a total CO 2 storage capacity in excess of 10 MMt. This can be achieved in a project span ranging from 4.5 years (water extraction, no oil production) to 20 years (EOR with bottom water extraction). Time, date Cumulative Water SC, m 3 Cumulative Gas SC, m 3 1985 1990 1995 2000 2005 2010 2015 0.00e+0 5.00e+4 1.00e+5 1.50e+5 2.00e+5 2.50e+5 3.00e+5 3.50e+5 4.00e+5 4.50e+5 5.00e+5 0.00e+0 2.00e+7 4.00e+7 6.00e+7 8.00e+7 1.00e+8 Cumulative Water SC 100_8-13_mon_discwaterinj (history) Cumulative Water SC 100_8-13_mon_discwaterinj (simulation) Cumulative Gas SC 100_1-13_gasinjector (history) Cumulative Gas SC 100_1-13_gasinjector (simulation) Time, date Well Bottom-hole Pressure, kPa 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 Well Bottom-hole Pressure 100_8-13_mon_disc (history) Well Bottom-hole Pressure 100_8-13_mon_disc (simulation) Well Bottom-hole Pressure 100_8-13_mon_discwaterinj (history) Well Bottom-hole Pressure 100_8-13_mon_discwaterinj (simulation) Well Bottom-hole Pressure 100_1-13_inj (history) Well Bottom-hole Pressure 100_1-13_inj (simulation) Well Bottom-hole Pressure 103_1-13_prod (history) Well Bottom-hole Pressure 103_1-13_prod (simulation) Time, date Cumulative Oil SC, m 3 Cumulative Gas SC, m 3 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 0.00e+0 5.00e+4 1.00e+5 1.50e+5 2.00e+5 2.50e+5 0.00e+0 2.00e+7 4.00e+7 6.00e+7 8.00e+7 Cumulative Oil SC (history) Cumulative Oil SC (simulation) Cumulative Gas SC (history) Cumulative Gas SC (simulation) Cumulative Water SC (history) Cumulative Water SC (simulation) Time, date Cumulative Gas Mass (CO 2 ) SC, kg Gas Rate SC, m 3 /day 2010 2015 2020 2025 2030 0.00e+0 1.00e+10 2.00e+10 3.00e+10 4.00e+10 0.00e+0 2.00e+6 4.00e+6 6.00e+6 8.00e+6 1.00e+7 1.20e+7 1.40e+7 CO 2 Injected (BHP Constraint = 300 psi) CO 2 Produced (BHP Constraint = 2068 kPa [300 psi]) CO 2 Injected (BHP Constraint = 14,478 kPa [2100 psi]) CO 2 Produced (BHP Constraint = 14,478 kPa [2100 psi]) Acid Gas Injection Rate (BHP Constraint = 14,478 kPa [2100 psi]) Acid Gas Production Rate (BHP Constraint =14,478 kPa [2100 psi]) Acid Gas Injection Rate (BHP Constraint = 2068 kPa [300 psi]) Acid Gas Production Rate (BHP Constraint = 2068 kPa [300 psi]) Time, date Field Oil Recovery, % Field Oil Rate SC, m 3 /day 1970 1980 1990 2000 2010 2020 2030 0 10 20 30 40 50 60 0 100 200 300 400 OiI Recovery (BHP Constraint = 2068 kPa [300 psi]) Oil Rate SC (BHP Constraint = 2068 kPa [300 psi]) Water Rate SC (BHP Constraint = 2068 kPa [300 psi]) Oil Recovery (BHP Constraint = 14,478 kPa [2100 psi]) Oil Rate SC (BHP Constraint = 14,478 kPa [2100 psi]) Water Rate SC (BHP Constraint = 14,478 kPa [2100 psi]) Predicted Oil Recovery, Field Oil, and Rate (existing EOR configuration with water extraction) Amounts and Rates of Injected and Produced CO 2 (existing EOR configuration with water extraction) Oil Saturation and Total Gas per Unit Area (2012-06-01), EOR with Bottom Water Extraction Oil Saturation and Total Gas per Unit Area (2032-06-01), EOR with Bottom Water Extraction Cumulative Gas Mass(CO 2 ) SC (EOR with bottom water extraction well) Cumulative Gas Mass(CO 2 ) SC (EOR with bottom water extraction well) Acid Gas Injection Rate (EOR with bottom water extraction well) Acid Gas Production Rate (EOR with bottom water extraction well) Field Water Rate (EOR with bottom water extraction well) Water Rate SC (Bottom water extraction well) Time, date Cumulative Gas Mass(CO 2 ) SC, kg Gas Rate SC, m 3 /day Water Rate SC, m 3 /day 2010 2015 2020 2025 2030 0.00e+0 2.00e+9 4.00e+9 6.00e+9 8.00e+9 1.00e+10 1.20e+10 0.00e+0 2.00e+6 4.00e+6 6.00e+6 8.00e+6 1.00e+7 1.20e+7 1.40e+7 0 200 400 600 800 1,000 1,200 1,400 Time, date Field Oil Recovery, % Field Oil Rate SC, m 3 /day 1970 1980 1990 2000 2010 2020 2030 0 10 20 30 40 50 60 0 100 200 300 400 Field Oil Recovry (EOR with bottom water extraction well) Oil Rate SC (EOR with bottom water extraction well) Oil Rate SC (Water Extraction Well) C A N A D A U N I T E D S T A T E S
Transcript of A Simulation Study of Simultaneous Acid Gas EOR and CO2 Storage at Apache… · 2015-10-28 ·...
A Simulation Study of Simultaneous Acid Gas EOR and CO2 Storage at Apache’s Zama F Pool
Dayanand Saini, Damion J. Knudsen, James A. Sorensen, Charles D. Gorecki, Edward N. Steadman, and John A. HarjuEnergy & Environmental Research Center, University of North Dakota, Grand Forks, North Dakota
EERCEnergy & Environmental Research Center®
Putting Research into Practice
© 2012 University of North Dakota Energy & Environmental Research CenterGHGT-11 – 2012
AbstractThe Plains CO2 Reduction (PCOR) Partnership is working with Apache Canada Ltd. (Apache) to validate the stored amount of CO2 during ongoing enhanced oil recovery (EOR) operation at the F pool of the Zama oil field situated in northwestern Alberta, Canada. Apache is capturing CO2 and H2S from a nearby gas-processing plant and injecting this stream into the F pool for simultaneous EOR and CO2 storage. Acid gas injection was initiated in December 2006 and is continuing to date. The present compositional flow simulation study aims to evaluate ways for maximizing incremental oil recovery and CO2 storage capacity in this depleted and closed pinnacle reef structure.
Two different versions (Version 1 and Version 2) of a constructed static geologic model were used for performing dynamic simulations. In the first simulation scenario that used, the Version 1 static model, additional storage capacity gain by pressure management through water extraction (no oil production) from the water zone below the oil–water contact (OWC) was investigated. The results clearly indicate the viability of formation water extraction for increasing storage capacity in a closed geologic structure. The second iteration of the constructed static geologic model (Version 2) was chosen for simulating cases of continuing the current EOR scheme with and without a bottom water extraction well. A fivefold (0.30 million metric tonnes [MMt] to 1.22 MMt) increase in CO2 storage capacity was observed with a bottom water extraction well compared to the case with no bottom water extraction well. This scheme also results in an incremental EOR recovery of 22.1% in the next 20 years, which is 5% more compared to the case of the existing EOR scheme (no bottom water extraction well).
With over 700 pinnacle reef structures (oil-bearing or water-bearing) in the Zama subbasin, a careful selection of pinnacle structures similar to the F pool may provide significant storage capacity gain through water extraction from the underlying water zone (aquifer) while achieving a significant increase in oil recovery.
Petrophysics
• History matching was performed with P10 OOIP (original oil in place) static model realization.
• A combination of object modeling and MPS workflow was used for spatial distribution of reef and nonreef facies in the static model.
• The adjusted parameters include vertical permeability, well productivity indices, and volume modifier for the reef structure below the OWC, along with a numerical aquifier at the bottom of the structure.
History Matching (Version 2 model)
Low-Permeability Rock Type Facies
High-Permeability Rock Type Facies
Input Output
GR
NPH
I
PHO
B
PEF
DT
RT RXO
Faci
es
PHE
Kh Kv
Perf
s
Swn
Son
Sw So
00.10.20.30.40.50.60.70.80.91
00.10.20.30.40.50.60.70.80.9
1
0 0.2 0.4 0.6 0.8 1
Kro
g
Krg
Sl, fraction
Low-Permeability Rocks (gas/oil rel. perm.)
Krg (initial)Krog (initial)Krg (history-matched)Krog (history-matched)
00.10.20.30.40.50.60.70.80.91
00.10.20.30.40.50.60.70.80.9
1
0 0.2 0.4 0.6 0.8 1
Krw
Kro
w
Sw, fraction
Low-Permeability Rocks (oil/water rel. perm.)
Krow (initial)Krw (initial)Krow (history-matched)Krw (history-matched)
00.10.20.30.40.50.60.70.80.91
00.10.20.30.40.50.60.70.80.9
1
0 0.2 0.4 0.6 0.8 1
Kro
g
Krg
Sl, fraction
High-Permeability Rocks (gas/oil rel. perm.)
Krg (initial)Krog (initial)Krg (history-matched)Krog (history-matched)
00.10.20.30.40.50.60.70.80.91
00.10.20.30.40.50.60.70.80.9
1
0 0.2 0.4 0.6 0.8 1
Krw
Kro
w
Sw, fraction
High-Permeability Rocks (oil/water rel. perm.)
Krow (initial)Krw (initial)Krow (history-matched)Krw (historty-matched)
Simultaneous CO2 EOR and Storage
0
20000
40000
60000
80000
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140000
0
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4000
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8000
10000
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14000
Cum
ulat
ive
CO2 In
ject
ion,
met
ric
tonn
es
Cum
ulat
ive
Oil,
m3
Date
Cumulative Oil and Injected CO2 Zama F Pool
Cumulative Oil Production (m3)Cumulative Acid Gas Injection (Metric tonnes)Cumulative CO2 Injection (metric tonnes)Cumulative CO2 Production (metric tonnes)
Net CO2 Stored
PVT (pressure, volume, and temperature) Modeling• An 11-component Peng–Robinson equation of state (EOS) PVT model was developed to use in the
compositional simulation.
• Simulated minimum miscibility pressures (MMPs) were 4.1% higher and 5.5% lower than the measured values for pure CO2 and acid gas (80% CO2 + 20% H2S) mixture, respectively.
1.00
1.05
1.10
1.15
1.20
1.25
0
10
20
30
40
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60
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0 5000 10000 15000 20000 25000 30000 35000 40000
Rela
tive
Oil
Volu
me
(RO
V) ,r
m3 /m
3
Gas
–Oil
Ratio
(GO
R), m
3 /m3
Pressure, kPa
Di�erential Liberation TestRegression Summary
Final GOR Init. GOR Exp. GOR
Final ROV Init. ROV Exp. ROV
0.001
0.002
0.003
0.004
0.005
0 5000 10000 15000 20000 25000 30000 35000 40000
Oil
Visc
osit
y, P
a-s
Pressure, kPa
Di�erential Liberation CalculationRegression Summary
Final Oil Visc. Init. Oil Visc. Exp. Oil Visc.
Static Modeling Workflow
Step 4. Form Reservoir Model
Anhydrite Wackestone/Packstone Grainstone/Floatstone/Rudstone
(10s of m-to-km scale)
Per
mea
ble
Faci
esP
erm
eab
leFa
cies
Tig
ht
Faci
es
(nm-to-mm scale)Step 2. QEMSCAN
(cm-to-m scale)
Step 3. Formation MicroimagingLog Processing and Petrophyscics
Step 1. Micro-CT scan(nm-to-µm scale)
DolomiteBackgroundCalciteOthersQuartzHiBSEHalitePore
Porosity Matrix
The Sequential Gaussian simulation algorithm was use to populate reservoir properties in the model.
History Match Results for Cumulative Oil, Water, and Gas Volumes
Actual and Simulated Well Bottomhole Pressures (8HPs)
History Match Results for Cumulative Volumes of Injected Acid Gas and Water
Predictive Simulation ResultsFormation Water Extraction Assisted by Acid Gas Injection (no oil production), Version 1 model
Existing EOR Configuration (one gas injection and two production wells) Two scenarios with minimum well BHP (bottomhole pressure) constraint of 2068 kPa (300 psi ) and 14,478 kPa (2100 psi) at production wells
0.08
0.81
1.08
1.05
1.04
0.85
1.02
0.05
0.47
0.62
0.68
0.69
0.49
0.60
0.62
0.85
0.91
0.94
0.72
0.84
0.00 0.20 0.40 0.60 0.80 1.00 1.20
One Injector (0.113 MMt/year) No Extractor, (Case 1)
One Injector (0.113 MMt/year)One Extractor (Location Y, 516 m3/day), (Case 2)
One Injector (0.113 MMt/year)One Extractor (Location Z, 516 m3/day), (Case 3)
One Injector (0.113 MMt/year)One Extractor (Location Z, 429 m3/day), (Case 4)
One Injector (0.113 MMt/year)One Extractor (Location Z, 397 m3/day), (Case 5)
One Injector (0.227 MMt/year)One Extractor (Location Z, 1144 m3/day), (Case 6)
One Injector (0.227 MMt/year)
xE6 Volume or Mass of Injected Acid Gas and Extracted Water, Closed Boundary System
Cumulative Extracted Water Volume at Reservoir Conditions, m3
Cumulative Injected Acid Gas Mass (Storage Capacity) at Standard Conditions, tonnesCumulative Injected Acid Gas Volume at Reservoir Conditions, m3
Two Extractors (Locations Z and Z1, 1144 m3/day), (Case 7)
Initial Oil Saturation
Oil Saturation at the End of History Match Period (2012-06-01)
Gas Saturation at the Start of Gas Injection (Dec. 2006)
Gas Saturation at the End of History Match Period (2012-06-01)
Total Gas per Unit Area (m) at the End of History Match Period (2012-06-01)
Gas Saturation (2032-06-01)1 Total Gas per Unit Area (m) (2032-06-01)1
Total Gas per Unit Area (m) at the Start of Gas Injection (Dec. 2006)
Oil Saturation (2032-06-01)1
1 After 20 years of EOR operations, minimum BHP constraint of 2068 kPa (300 psi) at production well.
Additional CO2 Storage Capacity Gain Through Water ExtractionOne water extraction well completed in bottom water zone with existing EOR configuration (one gas injection and two oil production wells).
Reservoir Pressure Behavior During Acid Gas EOR and 50-year Postinjection Period
Predictive Simulation Results (continued)
Variable Continuing current EOR configuration
Current EOR configuration with bottom water extraction well (completed [perforation at the bottom of the
structure] in the water zone below OWC)
Minimum BHP constraint of
2068 kPa (300 psi) at production wells
Minimum BHP constraint of 14,478 kPa (2100 psi) at production wells
Minimum BHP constraints of 2068 kPa(300 psi) at production wells and 14,478 kPa (2100 psi) at water extraction well
Incremental oil recovery (%) 16.2 12.6 22.1
Injection/production duration, years
20 20 20
Cumulative CO2 injected (70% of total acid gas injection), MMt
14.58 9.15 11.52
Cumulative CO2 produced, MMt 14.37 8.85 10.30
Net CO2 stored, MMt 0.21 0.30 1.22
Oil produced, m3 (MMstb) 1.98e4 (0.70) 1.55e4 (0.55) 2.69e4 (0.95)
Water produced, m3 (MMstb) 8.69e4 (3.07) 3.31e4 (1.17)2.223e5 (7.86)
Time, date
Ave
rage
Res
ervo
ir Pr
essu
re, k
Pa
1970 1980 1990 2000 2010 2020 2030 2040 2050 2060 2070 2080 2090 21005,000
10,000
15,000
20,000
25,000
30,000
BibliographyBuschkuehle M, Haug K, Michael K, Berhane M. Regional-scale geology and hydrogeology of acid-gas enhanced oil recovery in the Zama oil field in Northwestern Alberta. Report prepared by Alberta Energy and Utilities Board and Alberta Geological Survey, Canada, for the Plains CO2 Reduction Partnership at the Energy & Environmental Research Center, 2007.
Burke L. PCOR project Apache Zama F pool acid gas EOR & CO2 storage. Report prepared by RPS Energy Canada for the Energy & Environmental Research Center, 2009.
Knudsen DJ, Saini D, Gorecki CD, Peck WD, Sorensen JA, Steadman EN, Harju JA. Using multiple-point statistics for conditioning a Zama pinnacle reef facies model to production history. Poster presented at American Association of Petroleum Geologists (AAPG) annual conference and exhibition, Long Beach, CA, 2012.
Asghari K. Zama Keg River F pool field-scale CO2-flood simulation study. Report prepared for Apache Canada Ltd., 2005.
AcknowledgmentsThis material is based upon work supported by the U.S. Department of Energy National Energy Technology Laboratory under Award No. DE-FC26-05NT42592. Financial support from the U.S. Department of Energy to perform this work is greatly appreciated. The authors would like to thank Apache for providing necessary data to perform this work. The generous software support of Schlumberger and Computer Modelling Group Ltd. is gratefully acknowledged. The authors acknowledge Megan Grove and the members of the EERC’s Editing and Graphics staff for their help with poster preparation.
SummaryThe results of detailed static and geologic modeling performed in this study suggest that water extraction from underlying water zone (aquifer) can effectively be used for additional gain in both oil recovery and CO2 storage capacity in a closed system like the Zama F pool. The availability of additional pore space in the water zone below the OWC through controlled water extraction has resulted in a significant increase in F pool storage capacity. A combination of topdown gas injection EOR coupled with bottom water extraction appears to provide a new way to increase overall recovery efficiency and storage capacity in such reservoirs. In view of the high salinity of the formation water, produced water can be injected into another formation if a suitable completion strategy like downhole water sink (DWS) is used to complete water extraction wells. With over 700 pinnacle reef structures in the Zama subbasin, a careful selection of eight (EOR with bottom water extraction) to 16 (water extraction, no oil production) can provide a total CO2 storage capacity in excess of 10 MMt. This can be achieved in a project span ranging from 4.5 years (water extraction, no oil production) to 20 years (EOR with bottom water extraction).
Time, date
Cum
ulat
ive
Wat
er S
C, m
3
Cum
ulat
ive
Gas
SC
, m3
1985 1990 1995 2000 2005 2010 20150.00e+0
5.00e+4
1.00e+5
1.50e+5
2.00e+5
2.50e+5
3.00e+5
3.50e+5
4.00e+5
4.50e+5
5.00e+5
0.00e+0
2.00e+7
4.00e+7
6.00e+7
8.00e+7
1.00e+8Cumulative Water SC 100_8-13_mon_discwaterinj (history)Cumulative Water SC 100_8-13_mon_discwaterinj (simulation)Cumulative Gas SC 100_1-13_gasinjector (history)Cumulative Gas SC 100_1-13_gasinjector (simulation)
Time, date
Wel
l Bot
tom
-hol
e Pr
essu
re, k
Pa
1970 1975 1980 1985 1990 1995 2000 2005 2010 20150
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000Well Bottom-hole Pressure 100_8-13_mon_disc (history)Well Bottom-hole Pressure 100_8-13_mon_disc (simulation)Well Bottom-hole Pressure 100_8-13_mon_discwaterinj (history)Well Bottom-hole Pressure 100_8-13_mon_discwaterinj (simulation)Well Bottom-hole Pressure 100_1-13_inj (history)Well Bottom-hole Pressure 100_1-13_inj (simulation)Well Bottom-hole Pressure 103_1-13_prod (history)Well Bottom-hole Pressure 103_1-13_prod (simulation)
Time, date
Cum
ulat
ive
Oil
SC, m
3
Cum
ulat
ive
Gas
SC
, m3
1970 1975 1980 1985 1990 1995 2000 2005 2010 20150.00e+0
5.00e+4
1.00e+5
1.50e+5
2.00e+5
2.50e+5
0.00e+0
2.00e+7
4.00e+7
6.00e+7
8.00e+7Cumulative Oil SC (history)Cumulative Oil SC (simulation)Cumulative Gas SC (history)Cumulative Gas SC (simulation)Cumulative Water SC (history)Cumulative Water SC (simulation)
Time, date
Cum
ulat
ive
Gas
Mas
s (C
O2)
SC, k
g
Gas
Rat
e SC
, m3 /d
ay
2010 2015 2020 2025 20300.00e+0
1.00e+10
2.00e+10
3.00e+10
4.00e+10
0.00e+0
2.00e+6
4.00e+6
6.00e+6
8.00e+6
1.00e+7
1.20e+7
1.40e+7
CO2 Injected (BHP Constraint = 300 psi)CO2 Produced (BHP Constraint = 2068 kPa [300 psi])CO2 Injected (BHP Constraint = 14,478 kPa [2100 psi])CO2 Produced (BHP Constraint = 14,478 kPa [2100 psi])Acid Gas Injection Rate (BHP Constraint = 14,478 kPa [2100 psi])Acid Gas Production Rate (BHP Constraint =14,478 kPa [2100 psi])Acid Gas Injection Rate (BHP Constraint = 2068 kPa [300 psi])Acid Gas Production Rate (BHP Constraint = 2068 kPa [300 psi])
Time, date
Fiel
d O
il R
ecov
ery,
%
Fiel
d O
il R
ate
SC, m
3 /day
1970 1980 1990 2000 2010 2020 20300
10
20
30
40
50
60
0
100
200
300
400OiI Recovery (BHP Constraint = 2068 kPa [300 psi]) Oil Rate SC (BHP Constraint = 2068 kPa [300 psi])Water Rate SC (BHP Constraint = 2068 kPa [300 psi])Oil Recovery (BHP Constraint = 14,478 kPa [2100 psi])Oil Rate SC (BHP Constraint = 14,478 kPa [2100 psi])Water Rate SC (BHP Constraint = 14,478 kPa [2100 psi])
Predicted Oil Recovery, Field Oil, and Rate (existing EOR configuration with water extraction)
Amounts and Rates of Injected and Produced CO2 (existing EOR configuration with water extraction)
Oil Saturation and Total Gas per Unit Area (2012-06-01), EOR with Bottom Water Extraction
Oil Saturation and Total Gas per Unit Area (2032-06-01), EOR with Bottom Water Extraction
Cumulative Gas Mass(CO2) SC (EOR with bottom water extraction well)Cumulative Gas Mass(CO2) SC (EOR with bottom water extraction well)Acid Gas Injection Rate (EOR with bottom water extraction well)Acid Gas Production Rate (EOR with bottom water extraction well)Field Water Rate (EOR with bottom water extraction well)Water Rate SC (Bottom water extraction well)
Time, date
Cum
ulat
ive
Gas
Mas
s(C
O2)
SC, k
g
Gas
Rat
e SC
, m3 /d
ay
Wat
er R
ate
SC, m
3 /day
2010 2015 2020 2025 20300.00e+0
2.00e+9
4.00e+9
6.00e+9
8.00e+9
1.00e+10
1.20e+10
0.00e+0
2.00e+6
4.00e+6
6.00e+6
8.00e+6
1.00e+7
1.20e+7
1.40e+7
0
200
400
600
800
1,000
1,200
1,400
Time, date
Fiel
d O
il R
ecov
ery,
%
Fiel
d O
il R
ate
SC, m
3 /day
1970 1980 1990 2000 2010 2020 20300
10
20
30
40
50
60
0
100
200
300
400Field Oil Recovry (EOR with bottom water extraction well)Oil Rate SC (EOR with bottom water extraction well)Oil Rate SC (Water Extraction Well)
C A N A D A
U N I T E D S T A T E S
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